Wind Solar Electricity Report

SOLUTIONSWHITEPAPERSERIES
Wind and
Solar Electricity:
Challenges and
Opportunities
by
Paul Komor
University of Colorado
at Boulder
June 2009

Prepared for the Pew Center on Global Climate Change
by
Paul Komor
University of Colorado
at Boulder
June 2009
Wind and Solar Electricity:
Challenges and Opportunities

The author and the Pew Center would like to thank all those
who gave generously of their time to provide insightful
comments on drafts of this paper, including:
Dr. Paul Denholm (National Renewable Energy Laboratory);
Dr. Jay Apt (Carnegie Mellon University); Richard O’Connell
(Black & Veatch); Robert Gramlich and Michael Goggin
(American Wind Energy Association); and Mike O’Sullivan
(NextEra Energy Resources).

Contents
Executive Summary 1
I. Renewables’ Promise and Problems 3
A. Why Renewables? 4
B. Barriers to Increased Wind and Solar Electricity Generation 4
II. Wind and Solar Electricity Generating Technologies 6
A. Wind Electricity 7
B. Photovoltaics 9
C. Concentrated Solar Power (CSP) 11
III. Barriers to Increasing Wind and Solar Electricity Generation 12
A. Cost of Wind and Solar Energy Relative to Other Electricity Sources 12
B. Transmission Availability 13
C. Variability of Wind and Solar Electricity 15
IV. Overcoming Barriers to Wind and Solar Electricity 17
A. Make Wind and Solar Cost-Competitive 17
B. Overcome Transmission Constraints 22
C. Manage Variability 24
V. A High Wind and Solar Future: Scenarios and Implications 27
A. Current Trends: The “Business-as-Usual” Scenario 27
B. Alternative High-Renewables Scenarios 28
C. Implications of a High Wind and Solar Scenario 29
VI. Conclusions 33
Appendix 1: Cost Assumptions and Calculations 34
Appendix 2: Assumptions and Calculations for Figure 4 35
Endnotes 37

List of Figures
Figure 1 U.S. electricity production (TWh/yr) by energy source, 2007 (actual) 3
Figure 2 How carbon prices influence electricity costs 20
Figure 3 A “business-as-usual” forecast 27
Figure 4 Business-as-usual (BAU) scenario and some alternatives 28
Figure 5 High Wind Scenario 30
Figure 6 High Wind and Solar Scenario 32
List of Tables
Table 1 Wind and solar technology summary, plus natural gas for comparison 6
Table 2 Wind penetration rates 16
Table A1 Cost assumptions for LCOE calculation 34
Table A2 Assumed capacity factors for scenarios 35

1
Executive Summary
Electricity production is responsible for one third of total U.S. greenhouse gas (GHG) emissions. Therefore,
the considerable reductions in U.S. GHG emissions necessary to address climate change can only be achieved
through a significant shift to low- and zero-carbon sources of electricity, including renewable sources. Renewable
sources currently provide only a small fraction of U.S. electricity (eight percent total including conventional
hydropower; two percent excluding hydro). In the absence of significant new policies to promote renewable energy
or policies that put a price on carbon, a “business-as-usual” forecast suggests that renewables will supply 14
percent of U.S. electricity by 2030, with non-hydro renewables providing only 6 percent.
This paper focuses on wind and solar as energy sources for electricity production since they have enormous
resource potential, are accessible with existing technologies, are the focus of numerous current and proposed
policies, and face similar challenges to widespread deployment. The three major barriers to greater use of solar
and wind electricity are higher costs than many alternative electricity sources, insufficient transmission, and
management of the variable electricity output from these sources.
Electricity from wind is close to cost competitive with electricity produced from natural gas—depending
on natural gas prices, the availability of production tax credits, and other variables. Moreover, wind becomes
more cost competitive if policies, such as cap and trade, put a price on carbon. Electricity from solar
photovoltaic (PV) and concentrating solar power (CSP) power plants is significantly more expensive. These solar
technologies will not achieve significant market penetration unless costs drop significantly or policies either
subsidize or mandate use of these technologies. Some solar power cost reductions will occur with economies
of scale in production and learning curve effects; however, breakthroughs are needed in PV cell production
methods in order to allow for high-volume, low-cost PV manufacturing. Reasonably priced solar electricity
could revolutionize the electricity system; however, given the enormous wind resource, other renewable energy
options, and the well-documented technical and economic potential for end-use efficiency gains, the United
States could reach high levels of renewable penetration even without significant solar energy deployment.
Wind power plants must be located where the wind resource is sufficient, which may be far from existing
transmission lines or population centers. Significant increases in new wind electricity generation will require new
transmission lines. Transmission lines are expensive to build (two to four million dollars per mile), difficult to site,
and require approvals from multiple levels of government. Promising directions for addressing these problems
include innovative financing approaches that clarify who pays and how much, consideration of non-wires options
such as distributed storage that can reduce the need for transmission, and clarification of federal and state
roles in transmission planning and siting authority.

2
Wind and Solar Electricity: Challenges and Opportunities
Wind and solar power plants, unlike coal and natural gas power plants, cannot be scheduled to deliver
specified amounts of power at specified times. Instead, wind and solar power plants generate electricity when
the energy resources—the wind and sun—are available. Many electricity system operators see this variability as
a threat to system stability and reliability. However, several electricity systems are already operating with over 10
percent of their electricity coming from wind electricity. Recent analyses suggest that 20 percent is achievable
without threatening system reliability, although the added variability does impose costs.
There are three fundamental solutions to the variability challenge. The first is increasing the flexibility
of electricity supply options. This includes greater use of power plants that can rapidly adjust their output as
needed and contractual relationships with neighboring electricity systems for trading of electricity as needed.
The second is demand flexibility—using pricing and other contractual tools to influence or control the demand
for electricity. The third is physical storage of electricity and use of that stored electricity to “smooth” the
output of variable electricity sources. Several physical storage technologies are under development, but costs
are high and technical performance is uncertain.
Congress is considering proposals to require higher levels of renewable generation, and numerous
organizations have proposed aggressive renewable generation targets. Achieving much higher levels of wind
electricity, such as 20 percent by 2030 compared to less than two percent currently, would be challenging but not
unachievable. It would require annual wind turbine installations at a rate about double that achieved by the wind
industry in 2008. There appear to be no fundamental material, manufacturing, or labor barriers to achieving this.
Twenty percent wind by 2030 would require additional transmission spending of $3 to $4 billion per year,
about a 40 to 50 percent increase over current transmission spending. If these costs were included in the costs
of the electricity produced from wind, wind costs would need to increase by about 15 percent.
Studies suggest that the U.S. electricity grid can manage 20 percent wind penetration, although there would
be costs for doing so. These costs would add four to six percent to the cost of wind electricity.
These cost estimates are uncertain, but the available evidence suggests that transmission and variability
management would increase the cost of wind electricity by roughly 20 percent. This would make wind electricity
generally more expensive than that from natural gas, but in many cases still less expensive than that from new
nuclear or coal with carbon capture and storage (CCS) power plants. However, the relative cost of wind power and
electricity from natural gas will vary with natural gas prices and with a price on carbon.
Achieving higher penetration of solar power presents different challenges. One percent solar by 2030, for
example, would require annual solar installations of about 900 megawatt (MW)—two to three times higher than
that seen in 2008. This would be challenging if done as PV, but possible with CSP since large (100 + MW) CSP
plants have been proposed for the southwestern United States. The major challenge for PV and CSP is the first
costs of the technologies themselves, which are much higher for solar than for wind.

3
I. Renewables’ Promise and Problems
Electricity production accounts for one-third of U.S. greenhouse gas emissions.1
This is because almost
three quarters of electricity produced in the United States comes from fossil fuels—primarily coal and natural
gas (Figure 1). These fossil fuels, particularly coal, have high “carbon intensities,” which means that they emit
a large amount of carbon dioxide per unit of electricity produced.
Figure 1: U.S. electricity production (TWh/yr) by energy source, 2007 (actual)
Oil 1%
Non-Hydro
Renewables 2%
Hydro
6%
Nuclear
20%
Natural Gas
22%
Coal 49%
2007 (Actual) 4,137 TWh/yr
Note: TWh/yr = terawatt-hours per year
Source: DOE, March 20092
The U.S. electricity production system faces numerous challenges. Electricity demand continues to grow,
yet building new coal-fueled power plants that do not control GHG emissions is expensive, controversial, and
financially risky due largely to uncertainty over future climate policy. Increasing the use of natural gas for
electricity production could increase the cost of natural gas for industrial and residential use, may be financially
risky due to the volatility of natural gas prices, and raises concerns about increased dependence on imported
fuels.3
Furthermore, while natural gas is a less carbon-intensive fuel than coal, increased reliance on natural

4
gas alone is not nearly sufficient to achieve the GHG emission reductions needed from the electric power sector
to address climate change.4
Renewables are one of a portfolio of very low or zero-carbon technologies—which
could include nuclear power, carbon capture and storage, and energy efficiency—that together can significantly
reduce GHG emissions.
A. Why Renewables?
Renewable energy, including wind and solar electricity, offers several benefits compared to fossil-fueled
electricity generation.
• Zero-Carbon Electricity: Wind and solar, in contrast to fossil fuels, produce no direct GHG emissions
and, thus, offer the promise of zero-carbon electricity generation and a significant role in reducing
GHG emissions to avoid climate change.5
• Other Environmental Benefits: Wind and solar avoid many non-climate-related environmental impacts
associated with fossil-fueled electricity. They have no direct air emissions, they do not use large
amounts of water,6
and they do not require environmentally degrading fuel extraction.
• Fuel Diversification/Energy Security: Renewable electricity generation makes the electricity generation
system less reliant on coal and natural gas and thus less exposed to volatility in domestic and global
fuel markets.
• Economic Development: Many supporters of renewable energy highlight the potential for job creation
from investing in more renewable electricity generation.7
Although renewables, with the exception of hydropower, currently play a minor role in the U.S. electricity
supply (see Figure 1), supporters have long argued that the United States can and should make a rapid
transition to greater use of renewables.
This report focuses on wind and solar technologies as they have a very large remaining resource potential,
are commercially available and technically proven, and are the focus of considerable policy attention.
B. Barriers to Increased Wind and Solar Electricity Generation
Given that renewables have clear environmental advantages over fossil fuels, what is holding
renewables back?
It is useful to first point out factors that are not barriers. The United States is not significantly constrained
by the technical potential of the renewable resources themselves. By one estimate, for example, the United
States has more than 8,000 gigawatts (GW) of available on-shore wind power potential resource, compared to
a current total U.S. electricity generating capacity of about 1,000 GW.8
Potential solar resources are similarly
massive. In theory, solar panels covering less than 10 percent of Colorado, for example, could provide enough
electricity to power the entire United States.9
Commercially available technologies exist that convert renewable

5
resources into electricity. Many of these technologies are widely available, reliable, and technically proven;
although they are not necessarily cost-effective at this time (see discussion below).
The barriers are, rather, related to what can broadly be called “implementation.” Specifically, they include:
• High costs: Solar photovoltaic (PV) and concentrating solar power (CSP) generating plants, for
example, produce electricity at costs significantly higher than for electricity produced from wind or
fossil-fueled power plants.
• Transmission: Transmission lines carry electricity from power plants to cities, industry, and other
locations where it is needed. As explained below, utility-scale wind and solar power plants are often
located more remotely than fossil-fueled plants. Therefore, they require construction of new, expensive,
and controversial transmission lines—and this has proven very difficult.
• Variability/intermittency: The wind and the sun are variable resources, meaning that their availability
as an energy source fluctuates due to weather patterns, clouds, and cycles of day and night. The
electricity output from power plants dependent on these variable resources varies accordingly. The
demand for electricity, however, does not follow the same pattern. In the case of wind electricity,
electricity generation is sometimes greatest at night when electricity demand is lowest.
There are other barriers as well, including siting and permitting challenges for the renewable power plants
themselves and for the transmission lines that connect them to the grid, higher perceived technical risk, high
ratio of capital to operating costs, and policy uncertainty. However, the three barriers noted above—higher costs,
the need for new transmission capacity, and variability of output—are currently the most significant and thus
are the focus of this report.

6
II. Wind and Solar Electricity Generating Technologies
Wind and solar are quite different in terms of current market penetration and costs (Table 1). This
section summarizes the current status, costs, and challenges for wind and for two distinct solar technologies:
photovoltaics (PV) and concentrating solar power (CSP).
Table 1: Wind and solar technology summary, plus natural gas for comparison
Technology
U.S. capacity,
2007 (GW)
U.S. generation,
2007 (TWh/yr)
Representative cost
(LCOE, in ¢/kWh) *
Challenges/constraints
Wind 16 32 9-12 Variability, Transmission access
Concentrating Solar 1 1 24-29
High price, Variability,
Transmission access
Utility-Scale Solar
Photovoltaic
(20 MW+)
1 1 28-42
High price, Variability,
Transmission access
Distributed Solar
Photovoltaic ( 10 kW)
1 1 46-59 High price, Variability
Natural Gas 395 685 5-10
Fuel price volatility, Carbon
emissions
* The approximate levelized cost of electricity based on electricity generated from a new plant built today. Does not include/reflect the production
tax credit (PTC) or investment tax credit (ITC). See Box: Measuring and Comparing Costs of Electricity Production and Appendix 1: Cost
Assumptions and Calculations for details.
Notes: TWh/yr = terawatt-hours per year. ¢/kWh = cents per kilowatt-hour. LCOE = levelized cost of electricity.
Sources: Generation and capacity from U.S. Department of Energy (DOE).10
Cost assumptions detailed in Appendix 1.

7
Measuring and Comparing Costs of Electricity Production
There are many ways to measure costs; all are imperfect. This report defines cost of electricity
production as the “levelized cost of electricity” (LCOE), in units of cents per kilowatt-hour (¢/kWh). This
can be thought of as a price per kWh that covers both the first costs of the technology itself, as well as the
ongoing fuel as well as operations and maintenance (OM) costs of keeping the technology operating. As
such, it allows for direct comparisons across generating technologies. This report excludes from the LCOE
calculation the many “soft” costs that typically vary dramatically by project, such as land acquisition and
permitting costs. Also excluded are subsidies such as the production tax credit (PTC) or the investment
tax credit (ITC), as they are policy-dependent and distort cost comparisons. Finally, excluded as well are
the costs of new transmission that might be needed to accommodate the plant, as well as any variability-
related costs the plant might impose on the electricity system. (These costs however are estimated
separately; see discussion below).
LCOE is a useful metric that allows for comparisons across generating technologies. It does however
need to be used carefully, as it is not a direct measure of “value.” For example, a kWh from a natural gas
plant might be perceived as having greater value to the electricity system than a kWh from a wind turbine
because it is dispatchable—able to be turned on and off as needed. Similarly, a kWh from a wind turbine
may be seen as more valuable as there is no CO2 resulting from the generation of that kWh.
The specific assumptions and calculations for the LCOE estimates shown in Table 1 are detailed in
Appendix 1: Cost Assumptions and Calculations.
A. Wind Electricity
In recent years, wind electricity has seen a phenomenal boom. In 2008 alone, 8.5 GW of wind power
were installed in the United States, representing a 50 percent increase in U.S. wind capacity.11
After many
years in which the technical and environmental promise of wind clearly exceeded the commercial reality, wind
has turned the corner and is now a commercially proven, reliable, and cost-competitive option12
for producing
utility-scale electricity.
Large wind turbines typically start producing electricity when wind speeds reach about nine miles per hour
(mph) (four meters per second [m/s]) and reach their rated output at wind speeds of about 33 mph (15 m/s).
Therefore, any area with sustained wind speeds of greater than 10 to 15 mph may be able to support a wind
turbine. Such sites are surprisingly prevalent. Currently, 35 of the 50 U.S. states have installed utility-scale
wind turbines.13

8
The 25 GW of currently installed (end of 2008) wind capacity in the United States exploits a trivial fraction
of the total U.S. wind resource. A U.S. Department of Energy study14
estimates that the United States has the
technical potential for 8,000 GW of onshore wind and 4,000 GW of offshore wind.15
Just 12 percent of this
would provide enough electricity to meet the entire U.S. electricity demand.16
1. Wind Electricity Costs
How much does wind electricity cost? This report estimates the cost of wind electricity, excluding the
production tax credit (PTC),17
at nine to 12 ¢/kWh (see Table 1 and Box: Measuring and Comparing Costs of
Electricity Production). It is critical to note that this price is “typical” or “representative,” and that a specific
project’s costs may fall outside this range.
It is likely that any future wind electricity cost reductions will be modest. Wind turbine technology is
close to mature, and it already benefits from the inherent efficiencies of large-scale production. Although wind
turbines will continue to be refined and improved, costs reflect in large part the raw materials and construction/
assembly requirements, which cannot be further reduced significantly.18
2. Wind’s Strengths and Weaknesses
All electricity sources, renewable and nonrenewable, have strengths and weaknesses. Ideally, these factors
would be reduced to costs and benefits and could be combined to yield a final total or “societal” benefit-cost
assessment. In reality, however, it is often impossible to reduce these factors to financial terms, as their valuation
can be subjective and situation dependent. These factors are therefore discussed here separate from costs.
Wind electricity’s major strength is that it is a zero-carbon energy source19
with a per-kilowatt-hour cost that
is close to that of new fossil fuel-fired generation. Wind electricity has other attractive features as well:
• Utility-scale wind farms can be sized from about 10 MW to up to hundreds of megawatts,20
and
additional capacity can easily be added in stages.
• Wind electricity has no emissions, little noise, and no waste products, and it is compatible with many
land uses, including agriculture and grazing.
• Wind farms can be built quickly—in less than a year, typically.
Wind electricity also has some significant problems, notably:
• The wind resource overall is very large; however, wind farms must be sited where wind is sufficient,
which may be very far from population centers or transmission lines.
• There can be local opposition to siting of wind farms, primarily due to visual impacts.
• The electricity production from wind turbines is variable (see discussion below).
• As with any form of development, wind farms can have negative impacts on wildlife and natural
habitat. Moreover, wind farms require more area per MWh than many other electricity generation
technologies.

9
3. Wind’s Future
With a large and untapped wind resource, wind electricity per-kWh costs falling closer to that of new
fossil-fueled electricity, and an environmentally friendly image, wind electricity has a promising future. Most
projections of renewable electricity generation find wind to be a primary source of expanded renewable
generation.
B. Photovoltaics
Photovoltaics (PV) use various materials—most frequently silicon—to convert sunlight directly into
electricity. PVs are quiet, have no moving parts, can be installed very quickly, and can be sized to power
anything from a single light to an entire community. However, they are quite expensive, with current costs
ranging from 28 to 42¢/kWh for large grid-connected systems (see Table 1). Although costs have come down
considerably in recent years and will continue to drop, PVs are currently nowhere near cost-competitive with
fossil fuels in the vast majority of circumstances.
U.S. installed PV capacity at the end of 2008 was about 800 MW,21
which generates roughly the same
amount of electricity as one mid-size natural gas power plant. Although PV installations are growing rapidly,
photovoltaics currently supply much less than one percent of U.S. electricity consumption.
The solar resource is huge and could technically supply U.S. electricity needs many times over. For
example, as noted above, solar panels covering an area equal to less than 10 percent of Colorado could provide
enough electricity to power the entire United States. Such a system, however, would be immensely impractical
for numerous reasons, including that it would not generate electricity at night and that it could require massive
construction of new transmission lines.
1. Photovoltaic Costs
One sees widely varying costs for PV-sourced electricity, for several reasons:
• How cost is defined. Calculation of cost per watt includes only first (initial) costs and does not include
operating and maintenance costs. Calculation of cost per kilowatt-hour, in contrast, does incorporate
these factors but also requires assumptions about lifetimes and discount rates.
• What’s included. A complete PV system requires not just the photovoltaic cells but also many other
components such as inverters, transformers, and wiring.22
• Whether it is an actual or projected cost. There can be a large difference between what costs might be
in the future and what they really are today.
• The size and application of the system. In general, the larger the system, the lower the per-kilowatt and
per-kilowatt-hour cost.

10
• Where it is located. Although photovoltaics will operate anywhere, the more sunlight, the lower the per-
kilowatt-hour cost. A PV system located in the southwestern United States, for example, can produce
up to twice as much electricity as the same system located in the northeastern United States.23
• What technology was used. There are several different types of PV cells, and each has different costs
and performance characteristics.
• Whether the price reflects or includes subsidies. There is currently a federal investment tax credit for
PV systems,24
and several states provide significant subsidies as well.
This report estimates the costs of a utility-scale (20 MW) PV power plant at 28 to 42 ¢/kWh, not including
the federal investment tax credit (ITC) (See Table 1). Smaller (less than 10 kW) distributed PV systems have
somewhat higher costs which are estimated as 46 to 59 ¢/kWh, again excluding the ITC. PV cost estimates that
reflect the ITC will be considerably lower.
PV system costs overall decreased 3.5 percent per year from 1999 to 2007.25
Almost all of this cost
reduction was in non-module costs; the PV modules themselves showed little cost reduction.26
This does
not mean that module costs will not decrease in the future. There is currently considerable private-sector
investment in photovoltaics, and there are a number of promising approaches to producing PV cells at lower
costs. At least one manufacturer is claiming they can produce PV modules for under $1/watt27
—compared with
the $4/watt average module costs for installed U.S. systems in 2007.28
It is certainly possible, but by no means
assured, that PV costs could drop significantly in the future.
2. Photovoltaics’ Strengths and Weaknesses
Photovoltaic cells are noiseless and require little maintenance. They can be placed on rooftops or integrated
into building materials, and thus they raise few visual concerns. They can be sized to fit any application, from a
wristwatch to a multi-megawatt utility-scale system. Although their output will vary depending on the amount of
sunlight they receive, they can be installed anywhere the sun shines. The question of whether photovoltaics will
“work” in a specific geographical location is one of economics and cost-effectiveness, not technical feasibility.
And PVs, when used on rooftops and other distributed applications, can postpone the need for transmission and
distribution system upgrades.
The main problem with photovoltaics is their expense. As discussed above, their cost per unit of electricity
output is currently much higher than that of fossil-fueled generation and wind. In addition, their electrical
output is variable, meaning that their electricity production varies with the sunlight.
3. Photovoltaics’ Future
Photovoltaics’ high costs mean that they will supply only a small fraction of U.S. electricity needs, unless
those costs come down significantly or policies promote greater PV deployment via large subsidies or mandates.
As noted above, there is considerable private investment in new PV technologies, and the needed cost

11
reductions may occur. The future for this technology is uncertain and hinges on technical advancements that
would allow significant cost reduction (see discussion below).
C. Concentrated Solar Power (CSP)
Concentrated solar power plants (sometimes called “solar thermal” plants) concentrate the sun’s energy
onto a liquid carrier fluid (such as oil) and then use that hot fluid to heat water into steam and drive a turbine.
This approach to producing electricity is currently used at only a handful of locations worldwide; however, some
see it as a promising approach once the technology is refined and costs drop. The United States currently has
419 MW of CSP capacity. Most of this—354 MW—was built in California prior to 2000.29
1. CSP Costs
Only one utility-scale CSP plant has been built in the United States since 2000 (although several
additional plants are planned). This makes cost estimates highly uncertain. This report estimate the costs
(LCOE) of electricity from a CSP plant built today to be in the range of 24¢ to 29¢/kWh, excluding the
investment tax credit (see Table 1). These costs would decrease if more such plants were built, due to learning
curve effects and economies of scale in production.
2. CSP’s Strengths and Weaknesses
CSP plants can be built to provide dispatchable electricity (that is, electricity that can be produced when
it is needed rather than only when the sun provides sufficient energy), and can therefore be used to meet peak
demands. This can be done two ways. First, solar energy can be stored in the form of hot fluid for up to several
hours, and this fluid can then be used to generate electricity when needed. No currently operating plants in the
U.S. have this capability; nevertheless it is technically feasible. Alternatively, CSP plants can use natural gas to
heat the fluid when the sun is not available. This of course increases the carbon footprint of the plant.
CSP’s major weakness is its high costs, which stem from its technical complexity and need for large
reflective surfaces/areas. It also requires high sunlight levels, and therefore is geographically limited to the
U.S. Southwest. Therefore, significant new transmission would be required to deliver CSP electricity from the
Southwest to other parts of the country.
3. CSP’s Future
A number of CSP plants have been announced or planned in the U.S. Southwest, but it is not yet clear
how many (if any) of those plants will actually be built since high costs and transmission issues remain. If costs
come down, CSP could play a significant role in the Southwest (including the very large California market).

12
III. Barriers to Increasing Wind and Solar Electricity Generation
As noted above, there are three principal barriers to greater use of wind and solar electricity: high costs,
transmission availability, and variability of output. This section explains these challenges in further detail; the
next section outlines some solutions.
Who Decides What New Power Plants Get Built?
Changing how the United States generates electricity requires an understanding of how decisions are
made about what types of new power plants are built, and who makes those decisions.
The U.S. electricity system is a mix of regulation and competition.30
Most states have a traditionally
regulated system, in which regulated utilities generate, transmit, distribute, and sell electricity. State
regulators oversee major decisions by these utilities—including decisions to build, or buy the output from,
new power plants.
When considering new power plants, many state regulators use a “least-cost” process, in which
the various options (such as natural gas, coal, wind, and energy efficiency) undergo a detailed economic
analysis to determine which will provide the lowest-cost means of meeting electricity demand. In the
regulated system, it is the state regulators and the utility that most strongly influence new generation
decisions.
Some states use a more competitive system, in which utilities are not vertically integrated, and
generating companies compete with one another to sell electricity to distributors and end users. Some of
this electricity is sold in short-term bidding markets, while some is sold via longer-term bilateral contracts.
In this system, market prices for electricity play a larger role in determining new generation decisions.
A. Cost of Wind and Solar Energy Relative to Other Electricity Sources
The greatest single barrier to significant market penetration for solar PV and CSP is their high costs. As
shown in Table 1, there is a very large gap between the levelized costs of these technologies and those of
natural gas power plants, even if one assumes a high natural gas price.

13
As discussed above (see Box: Measuring and Comparing Costs of Electricity Production), levelized
technology cost (¢/kWh) is only one way to measure costs. A true societal cost that captured environmental
and other costs and benefits not captured in price might show a different pattern. However, investment and
purchase decisions are made largely on market costs, not societal costs. Therefore, solar PV and CSP will not
achieve significant market penetration unless first costs drop significantly, policies subsidize or mandate the
use of these technologies, or climate policies put a high price on carbon.
Costs are not as much of a barrier for wind turbines. As shown in Table 1, wind turbines can produce
electricity at a per-kWh cost much below that of PV and CSP. And, depending on prevailing natural gas prices
and other factors, wind electricity’s cost can be close to that of electricity from natural gas.
B. Transmission Availability
The U.S. electricity system was built to accommodate large, centrally located power plants and to provide
reliable, low-cost electricity to users. High-voltage transmission lines carry electricity from power plants to
large demand centers, transformers then reduce the voltage, and the electricity is then delivered to users via
distribution lines.
This system worked well for large (200 MW and larger) power plants and traditionally regulated, vertically
integrated utilities, but it is now showing its age. The introduction of competition in generation markets
increased the demand for longer-distance and interstate movements of electricity—something not foreseen, or
always easily accommodated, in our current transmission system. States have regulatory power over utilities
operating within their borders and have been unenthusiastic about interstate transmission lines (particularly if
these lines mean that low-cost electricity would be exported). And in restructured states (that is, states without
traditionally regulated, vertically integrated utilities), there has been little incentive for the private sector to
invest in new transmission lines.
In addition to these issues, utility-scale new wind and solar plants present particular challenges to the
transmission system. One is that wind and solar power plants must be located where the renewable resource is
sufficient—and this location may be far from any existing transmission lines and far from electricity users. This
is in contrast to fossil-fueled power plants, for example, which can be sited near existing transmission and/or
electricity users.
Another challenge is that wind and solar produce fewer kWh per kW of capacity (that is, they have lower
capacity factors) than many fossil fuel power plants. In other words, a wind or solar power plant will provide
less electricity per unit of generation capacity. So pricing transmission use by capacity means that wind may
pay more per unit of electricity delivered (kWh) than a fossil-fueled power plant. Whether or not such pricing is
discriminatory is a contentious issue; nevertheless, pricing of transmission by capacity, rather than generation,
can make it challenging for wind or solar to compete financially. Similarly, if a wind or solar power plant must

14
pay to reserve space on a transmission line, but is then unable to use that space because the wind is not
blowing or the sun is not shining, then that payment is lost. Dispatchable and baseload power plants do not
suffer from this form of risk.
The end result is a risk that existing wind projects will be unable to get their electricity to market and that
proposed projects will be unable to proceed due to the unavailability of transmission.
Clearly, new transmission lines would enable greater use of renewable energy. Why then are they not being
built? Barriers to new construction include:
• Jurisdictional conflicts and overlaps: Cities and counties control land use, states control intrastate
electricity, and the federal government controls interstate electricity. This makes for complex and time-
consuming permitting and paperwork requirements.
• Public opposition: Some see new transmission lines as ugly, environmentally damaging, and unsafe.
This leads to blocking of new line projects at the local and regional levels.
• High first costs: New transmission lines typically cost $2 million to $4 million per mile,31
or more
if lines are underground or very high voltage. Construction of new lines takes several years, at best.
Revenues, however, don’t start flowing until the line is operating, and these revenues are uncertain
and depend in part on state and federal-level regulators’ decisions on how transmission use is paid for.
This makes building transmission capacity a high-risk proposition—one that few, if any, private-sector
companies will take on without significant risk sharing or other government support.
Significant increases in new renewable electricity generation will require new transmission lines,32
and it
is very difficult to get these lines built. This is not a technology issue; rather, the problem is a complex one of
incentives, jurisdiction, and cost sharing.

15
Who Owns Transmission Lines?
In traditionally regulated states (see Box: Who Decides What New Power Plants Get Built?), vertically
integrated utilities generate, transmit, and distribute electricity. Those utilities usually own and operate
their own transmission lines. In other states, ownership varies. In many cases, a single company owns
and operates transmission and distribution systems. These companies are typically under state regulation,
although that regulation is limited to intrastate activities. The Federal Energy Regulatory Commission
(FERC) regulates interstate transmission of electricity through existing power lines; however, siting of these
lines is largely a local and regional matter. There are alternative, although less-common, transmission
ownership structures. A regulated company can provide transmission only, without generation or
distribution. In this structure, a separate regulated company provides distribution, while either competitive
companies or a single regulated company can provide generation. Alternatively, a “merchant” company
can own and operate transmission services.33
These companies typically do fall under FERC regulation, but
can be given leeway to charge rates based on market forces.34
Finally, some public utilities (such as local
government utilities and federal power administrations) own transmission lines.
C. Variability of Wind and Solar Electricity
When electricity users flip on the light switch, they expect the lights to come on. This expectation,
combined with the fact that it is very difficult to store electricity, means that utilities are left with the
challenging task of always producing exactly as much electricity as is demanded.
One essential tool utilities and electricity system operators use to ensure electricity supply equals electricity
demand is “dispatch,” meaning turning power plants up or down as needed. Many types of power plants—
natural gas and hydroelectric, for example—are “dispatchable.” Wind and PV, unfortunately, are not. Therefore,
from the perspective of the utility, wind or solar electricity may not be as valuable, or useful, as that from
dispatchable power plants, because utilities cannot necessarily depend on wind and solar plants to produce
electricity when it is needed. How much less valuable, how to measure that loss of value, and how much wind
and solar can contribute to total electricity needs are contentious questions.
Until recently, wind and solar energy provided such a small fraction of total electricity that their effects on
the electricity system were not noticeable. In the past few years, however, as wind electricity generation has
increased, concern over the effects of variable (also called intermittent) electricity sources has grown. Recent
research, coupled with accumulating experience, has shown the following:
• Wind electricity does not require 100 percent backup with dispatchable generation. That is, having
100 MW of wind electricity does not mean that one needs 100 MW of natural gas–powered generation

16
ready to go in case the wind suddenly stops. The wind is somewhat predictable, and the latest research
shows that wind does have some “capacity value,” meaning that it can provide some level of reliable
electricity.35
PV, too, has some capacity value. CSP with storage can have considerable capacity
value—in some cases, close to that of traditional fossil-fired power plants.
• Wind electricity can provide a significant fraction of total electricity without a reduction in system
reliability. In a number of U.S. states, and other countries, wind plays a major role in the overall
electricity mix (Table 2)—and those electricity systems are stable and reliable.
• Managing wind’s variability does add costs; however, these costs are modest. Many studies have
assessed the costs of managing wind’s variability and have found that wind imposes costs of
0.1¢ to 0.5¢/kWh on the system as long as wind accounts for about 30 percent or less of total
system capacity.36
Table 2: Wind penetration rates
State or region
Percentage of in-state or in-region
generation that comes from wind, 2007
Minnesota 7.5%
Iowa 7.5%
Colorado 6.1%
South Dakota 6.0%
Denmark 20%
Spain 12%
Portugal 9%
Ireland 8%
Source: U.S. DOE, 2008.37
Nonetheless, variability is a legitimate concern. The high (over 10 percent) wind penetration rates for
European countries, shown in Table 2, are made possible in part through cross-border transmission links.38
The
studies showing modest costs imposed by higher levels of wind are estimates, not actual measured costs. There
is very little real-world experience with high penetration rates of variable electricity resources.

17
IV. Overcoming Barriers to Wind and Solar Electricity
In order to ensure greater generation of wind and solar energy, they must be cost-competitive, transmission
constraints need to be resolved, and solutions to the variability of these renewable resources need to be
developed.
A. Make Wind and Solar Cost-Competitive
As noted above, wind electricity’s cost (LCOE, see Table 1 and Box: Measuring and Comparing Costs of
Electricity Production) is close to that of electricity from natural gas, depending on prevailing natural gas prices
and other factors. The principal barriers to greater use of wind electricity are instead primarily transmission
availability and output variability.
This is not true for either photovoltaics or concentrated solar power. As summarized in Table 1, utility-scale
photovoltaics can provide electricity at a levelized cost of 28 to 42¢/kWh, whereas concentrated solar power
costs 24 to 29¢/kWh. Neither of these is price-competitive with natural gas or wind, which are at 5 to 10¢/kWh
and 9 to 12¢/kWh respectively. (These cost estimates exclude major tax credits, see Appendix 1 for details.)
Decisions about new electricity generating technologies are driven in large part by costs. Solar is still a
niche technology because it is so expensive. It will remain a niche technology unless: (a) the costs of solar come
down significantly; (b) the costs of fossil-based electricity go up significantly (for example, due to regulations
that put a high price on carbon); or (c) solar is mandated through, for example, solar set-asides in renewable
portfolio standards (RPSs) or feed-in tariffs. These three options are discussed separately, below.
How are price reductions in new technologies achieved? One path is through continual refinements in
production processes and assembly methods. This typically occurs when production volumes increase and
competitive market forces provide financial incentives for price reductions. Wind turbines are a useful example
of this process. Wind turbines in 1980 were produced by a small number of small companies, the turbines
produced relatively expensive electricity (~40¢/kWh), and turbines were not always reliable or well engineered.
The transition to today’s low-cost and technically sophisticated turbines was not the result of any one technical
breakthrough but, rather, a long series of improvements, refinements, and advances.
This process only works, however, when one is essentially refining existing technologies, rather than coming
up with new ones. It is useful, therefore, to break the solar cost reduction challenge into two parts: refining
existing technologies and inventing new ones.

18
1. Refine Existing Technologies
Photovoltaics’ first costs (also called “initial” or “capital” costs) are typically $5,000 to $9,000/kW (see
Appendix 1). These first costs break down into two, roughly equal components: the PV modules themselves, and
the rest of the system—wires, support structures, inverters, and so on—commonly called “balance of system”
(BOS) components.39
It is likely that these BOS components would see significant reductions if the number
of installations increased significantly. Currently, many PV systems are custom-designed, and assembled and
installed by small companies that do not have time or money to invest in research to fine-tune them. These
BOS components fall into the “refining existing technologies” category, and cost reductions will likely occur if
production volumes increase.
Similarly, CSP systems make use of existing technologies and have considerable potential for large cost
reductions without the need for fundamental advances. This is not to minimize the challenge; CSP is not a
simple technology, and it will require considerable technical development to yield the needed cost reductions.
However, there is no “show-stopper,” and it is likely that these cost reductions would occur, given the right
incentives to the industry.
2. Invent New Technologies
The PV modules themselves, in contrast, are in need of some fundamental advances. The majority of PVs
sold today are “crystalline silicon”—a technology that requires considerable amounts of expensive processed
silicon, a complex and costly production process, and the need to wire individual cells together, which further
increases costs and complexity. Recent analyses of PV cost data show that module costs—predominantly
crystalline silicon—were essentially flat from 1998 to 2007.40
It is not clear that PV systems made with
crystalline silicon cells can achieve the cost reductions needed to become economically competitive with
natural gas or wind-based electricity.
A much more promising approach is “thin-film,” in which a very thin layer of photovoltaic material is
applied directly on a backing material (typically glass or steel). This process uses much less PV material, lends
itself to continuous manufacturing (thin-film PV can be produced in a continuous sheet for potentially lower
manufacturing costs than crystalline silicon PV), and may be able to be applied directly to windows, roofing and
siding materials, and other surfaces. There are a number of promising thin-film technologies and approaches,
some in commercial use, and more under development. More research, however, is needed to refine thin-film
production methods with the goal of low-cost, high-volume manufacturing of reliable and durable PV cells.

19
Given the enormous solar energy resource and thus the long-term potential for solar electricity to provide
substantial zero-carbon electricity, policies to promote or subsidize PV research and development (RD) are well
justified. As the private sector is already engaged, such policies should focus not on fundamental/theoretical
research but, rather, on building on the applied research already under way. Policy options include expanded
RD tax credits and greater funding of university/industry research collaborations. These policies should focus
on research into methods to manufacture low-cost PVs at high volumes. Deployment policies, in contrast,
raise questions as to the degree to which they are subsidizing higher-priced technologies that may not achieve
economic competitiveness.
3. Putting a Price on Carbon
Putting a price on carbon emissions (such as via a cap-and-trade program) would raise the costs of
traditional fossil-fueled electricity, thereby increasing the cost-competiveness of low-carbon alternatives. A clear
externality of fossil-fueled electricity is carbon: coal-fired power plants emit about one metric ton (tonne) of
CO2/MWh, and natural gas power plants emit about 0.5 tonnes of CO2/MWh. Wind and solar power plants, in
contrast, emit no CO2. In addition to any policies to promote renewable energy, reductions in greenhouse gas
emissions from across the economy can be achieved by putting a price on carbon as a carbon cap-and-trade
system or a carbon tax would do.41, 42
The degree to which a cap-and-trade system promotes renewables depends largely on where the cap is set,
how much the cap is decreased per year, and the resulting price on carbon. Putting a price on carbon makes
renewable electricity more competitive with electricity from coal and natural gas. A price on carbon could make
wind electricity less expensive than natural gas electricity, but it is unlikely to make solar a least-cost generation
option unless significant progress is made in reducing the cost of solar electricity. As shown in Figure 2, even
at a $50/tonne CO2 price, electricity from solar PV and solar CSP have higher costs (levelized cost of electricity,
LCOE) than electricity from other sources.
In interpreting Figure 2, one should note that it considers only the LCOE (see box above explaining
what LCOE does and does not include), that absolute and relative costs can vary significantly depending on
circumstances, and that cost estimates for nuclear and coal with carbon capture and storage include a significant
degree of uncertainty that is not reflected in Figure 2. Nonetheless, Figure 2 does illustrate that a price on carbon
makes wind power more cost competitive with other power sources but that even a significant price on carbon is
not expected to make current solar power technologies cost competitive in most cases.

20
Figure 2: How carbon prices influence electricity costs
0 10 20 30 40
0
4
8
12
16
20
24
30
32
36
Levelizedcostofelectricity(¢/kWh)
Carbon price ($/tonne CO2
)
IGCC coal with CCS
Natural Gas – high
Nuclear
Wind – middle
Conventional Coal
Natural Gas – low
Solar CSP
Solar PV
Notes: Costs will vary depending on location of plant, costs of capital, and other variables. “Solar PV” is solar photovoltaic. “Solar CSP” is
concentrating solar power. “IGCC coal with CCS” is integrated gasification with combined cycle coal with carbon capture and storage. Eighty
percent carbon capture assumed for CCS. Costs for solar PV, solar CSP, wind, and natural gas combined cycle are from Table 1. Midpoints from
the ranges in Table 1 are shown here. Costs for nuclear, conventional coal, and IGCC coal with CCS are author’s estimates, based in part on E3,
2007.43
Assumed carbon intensities are one tonne CO2/MWh for coal, and 0.5 tonne CO2/MWh for natural gas.
4. Regulatory Approaches
A third approach is to require the use of renewables. The predominant such policy approach in the United
States is the renewable portfolio standard (RPS). An RPS requires that a minimum percentage of electricity
come from renewables by a set date, and typically that percentage increases over time. For example, California’s
RPS requires that 20 percent of electricity come from renewables by 2010.44
More than half the states now
have RPSs, and federal legislation to set a national RPS is currently under consideration.
RPSs vary considerably by state. RPS attributes that vary include the percentage and date specifications,
penalties for noncompliance, definition of qualifying renewables, and breadth of coverage (for example, whether
the RPS covers municipal utilities). Some RPSs use “set-asides” (also called “carve-outs”), which require
that some subset of the required renewables come from specific technologies. For example, New Jersey’s
RPS requires that 22.5 percent of electricity come from renewables by 2021, with about one tenth of the

21
requirement “carved out” for solar. In states with solar set-asides, solar is being built as required; however, it is
not yet clear if these set-asides are building an enduring solar industry or driving significant cost reduction.
Germany’s Feed-in Tariff: Solar, But at What Price?
An alternative to the RPS is the “feed-in tariff:” a requirement that electricity providers purchase
electricity from renewable electricity generators at a mandated price. Feed-in tariffs are a popular policy
approach in Western Europe, with Germany’s feed-in tariff (called the Renewable Energy Law, REL) being
the most well known.
Germany’s REL requires utilities to purchase electricity from certain types of renewable generators,
and sets the price that utilities must pay. In 2006 utilities paid 52 to 72 US ¢/kWh for electricity from
solar PV systems, for wind the set price was 11 ¢/kWh.45
These prices generally decline over time.
Given these generous prices, it’s not a surprise that the REL has triggered a renewables boom in
Germany. Germany has more wind power (~22 GW)46
and more installed PV (~4 GW)47
than any other
country in Europe.
Clearly, if policy success is defined as the amount of new renewables built as a result of that policy,
then Germany’s REL is an astounding success. Renewable generators have clear profit margins and little
risk, as they are guaranteed a high and enduring price for their product. These generators can also access
relatively low-price capital, as lenders see little risk due to the high price and the fact that the customer is
a large, regulated, and stable entity. So renewable generators have flocked to the German market.
What’s less clear, however, is the REL’s overall economic impact. The high prices paid to renewable
generators mean that these generators face no direct competition (as utilities must buy from them, at
the regulated price), and thus have a reduced incentive for price reduction. The price paid to renewable
generators does not directly reflect market costs or market forces, but is instead set via a political process.
Overall, the REL has clearly driven large amounts of new renewables installations. What is less clear
is if the price paid for these renewables was as low as it could have been.
5. Markets and Policy Goals
Although solar electricity production technologies will need to achieve significant cost reductions to
become cost-competitive, the United States is well situated to accomplish this goal because:

22
• There is clearly a huge financial incentive/reward for industry: Retail electricity sales totaled $340
billion in 2007 in the United States alone.48
• Due to a number of aggressive state and federal policies, PV installations are growing rapidly.49
More
companies are entering the business, innovative financing mechanisms are being developed, and
installation techniques are improving—all necessary components of an effective industry.
When thinking about options to accelerate this process, it is useful to consider policy goals and market
functioning. Addressing climate change requires reducing economy-wide greenhouse gas emissions. Such
reductions will have to include large reductions in GHG emissions from the electric power sector. If the goal,
then, is low-carbon electricity at a reasonable cost, there are alternative approaches that can already provide
low- or zero-carbon electricity at costs competitive with fossil fuels (such as wind and efficiency).
More generally, it is not clear that aggressive policies to promote deployment of current PV technologies are
warranted. These technologies are still quite expensive relative to other options for reducing GHG emissions. If
deployment policies simply subsidize installations of current technologies without providing strong incentives
for cost reduction, then these policies are not building an enduring role for PV in the electricity market.
B. Overcome Transmission Constraints
New transmission lines are needed in order to extend the transmission system to remote locations that have
wind and/or solar resources and to allow for interstate flow of renewable-fueled electricity from wind- and solar-
rich regions to other regions.
1. Develop Innovative Financing
Building new transmission lines typically costs $2 million to $4 million per mile; however, there is revenue
associated with transmission. Once transmission is built, fees can be charged to those using it. Since there is
a long time gap between the start of construction and when revenue starts flowing, it is usually unclear at the
beginning who will pay these fees and how much they will pay, and these fees are influenced not just by market
forces but by regulatory decisions (such as public utility commission rulings). Therefore, attracting private
sector investment in new transmission projects will likely require significant public/government support, and will
certainly require better clarification of who pays and how much.
One way to clarify who pays and reduce perceived financial risk is to promote agreements among states,
and particularly among state utility regulators, that commit multiple states to ensure cost recovery for these
projects through, for example, an electricity bill surcharge. This surcharge could begin when construction starts,
rather than when electricity starts flowing through the line—reducing the time between investment and return
(such an approach has been used to fund power plants, although not without controversy). This approach should
stick closely to a user-pays philosophy—that is, those who expect to benefit (through, for example, receiving
low-priced wind electricity) should contribute financially.

23
Greater use of tax-advantaged financing, such as allowing for the use of tax-exempt bonds, is a promising
policy option for promoting new transmission, given the high cost of new transmission construction.50
More
generally, innovative ways to merge the strengths and abilities of the public and private sectors in large
infrastructure projects will be critical.
States—and state regulators—have little incentive to contribute to a transmission line if it means low-
priced electricity flows out of their state. However, if regulators were able to consider the larger economic
impacts of in-state renewables development, rather than only electricity price impacts, they might be more
supportive. State regulators could be encouraged to take a broader view of impacts when assessing multi-state
transmission projects.
2. Include the Non-Wires Option
Improved energy efficiency and growth in distributed generation will dampen the demand for new
transmission capacity. Looking further ahead, new technologies—notably plug-in hybrid electric vehicles
(PHEVs) and smart grids—may change the way electricity is priced and managed.
For example, PHEVs may provide short-term energy storage to smooth the output of wind power plants,
and smart grids may allow for demand response that reduces the need for new transmission. These “non-
wires” solutions (meaning they reduce or postpone the need for new transmission) should be considered in any
comprehensive analysis of new transmission needs.
The current U.S. electricity grid consists of a number of regional grids that operate largely independently,
and within these grids smaller “balancing areas” operate somewhat independently as well. Increasing
coordination both within and among regional grids, and providing incentives for sharing power when needed,
would ease management of variable resources like wind and solar.
3. Clarify Federal and State Roles
The Energy Policy Act of 2005 established a process whereby federal eminent domain authority could
be used to override state or local opposition to new transmission lines. In addition, that Act required the
Secretary of Energy to designate “National Interest Electric Transmission Corridors” (NIETC) in areas
experiencing transmission constraints. In response, DOE designate two large areas as such corridors. Public
and Congressional opposition to those designations was strong; 14 Senators signed a letter to the Chair of the
Senate Energy Committee arguing that DOE’s actions were inappropriate and calling for hearings. Clearly, the
appropriate balance between Federal, state, and local land use decision-making has not yet been found.
Congress could revisit the NIETC process, with extensive input from state and local governments. State and
local governments are unlikely to support a project that does not benefit them, so consideration should be given
to designing projects with wider benefits and compensation to affected parties who do not benefit.

24
Some have called for a “national power grid” as a way to overcome the state/federal conflicts and to
promote integrated operation of the electricity system. Congress has considered legislation that would further
increase the Federal role in transmission siting and construction.51
This is an ambitious proposal, and one
deserving further study. The experience of implementing the related section of the Energy Policy Act of 2005
(discussed above) suggests that such an approach will require extensive consultation with all stakeholders.
C. Manage Variability
The variability of wind and solar electricity reduces their value to electricity system operators, who must
continually match electricity supply with electricity demand. That variability also raises some concerns about
impacts on electricity system reliability.
Complicating the issue is considerable uncertainty over how much of a problem variability really is. As
discussed above, several electricity systems are operating with significant amounts (over 10 percent) of variable
electricity (mostly wind), and few systematic problems have emerged. Estimates of the costs of managing this
variable electricity suggest that the costs are low. Nevertheless, higher levels of variable electricity, such as 20
percent, will require changes in electricity system operation.
There are three fundamental approaches to this problem: supply flexibility (providing more or less
electricity as needed to accommodate the variable generation), demand flexibility (changing the demand for
electricity as needed), and storage.
1. Supply Flexibility
All electricity systems have some flexibility in the amount of electricity they can provide; this is how they
accommodate changes in electricity demand. This flexibility can come from power plants that can change
their output as needed, or from contractual relationships with neighboring electricity systems that allow for
exchanges of electricity between systems as needed. This is how some European countries (see Table 2) are
able to manage the large amounts of wind electricity in their systems: they can call on neighboring systems to
provide—or accept—electricity as needed.
One way to facilitate this contractual approach is to build and improve transmission links, as discussed
above. The more physical links between electricity systems, the more options there are for contractual
relationships to handle renewables’ variability. Similarly, combining the electrical output of several
geographically dispersed wind power plants yields a smoother total output that is worth more to electricity
system operators. Such combining is made possible by greater transmission availability.
A second option is to encourage transparency and disaggregation of grid operation costs. Currently,
traditionally regulated utilities typically manage their own generation and transmission systems, and the various
costs of wind integration are usually not broken out or monetized. If the costs of wind integration were broken

25
out, then it might encourage new solutions (either technical or contractual) that could provide these services
at a reasonable cost. Such markets are starting to develop in some parts of the United States, but they are not
yet widespread.52
2. Demand Flexibility
A small fraction of U.S. electricity demand is currently “controllable”—meaning that grid operators can
actually reduce that demand when needed to maintain electricity grid reliability. This option, called “demand
response” or “load management,” is typically used only when there are no remaining electricity supply options.
For example, on a hot summer afternoon, a utility may actually be in danger of running short of electricity.
In this situation, the utility may ask its large customers to reduce their electricity use, or may remotely cycle
(switch on and off) residential customers’ air conditioners.
The variability of wind and solar generation is conceptually similar to the variability in demand that
electricity systems already manage; and increases in demand flexibility (through, for example, real-time pricing
or other incentive programs) can be a cost-effective option for managing both sources of variability. Considering
demand response as an economic option—using it when it costs less than the alternatives—rather than just in
emergencies, should be given greater consideration.
3. Develop Physical Storage Options
Adding storage to the grid is another option for managing the variability of wind and solar electricity. For
example, when wind electricity output drops due to a reduction in wind speeds, an electricity storage system
could discharge stored electricity to make up for the reduction in wind electricity.
It is possible to store electricity; however, it is neither inexpensive nor simple. The only storage technology
currently in widespread use is pumped hydro, of which the United States currently has 22 GW.53
However,
it is unlikely that many more large pumped hydro systems will be built, due to the land requirements and
environmental impacts of building large new reservoirs. There are a number of new storage technologies under
development, both utility-scale and distributed (also called end-use storage). (See Box: Storage Technologies).
Physical storage is an area in which RD funding is appropriate, because low-cost electricity storage
could be a cost-effective means to accommodate the additional variability introduced by new wind and solar
electricity. Distributed storage could also reduce or postpone the need for transmission and distribution
system upgrades.

26
Electricity Storage Technologies
Electricity storage technologies can be divided into “utility-scale” (typically 10+ MW) and
“distributed” (less than one MW).
Research into utility-scale storage has been ongoing for many years, but with modest funding
and modest progress; the availability of low-cost natural gas peaking power plants reduced the need for
such storage. Interest has increased recently; however, no new utility-scale storage technologies have
yet emerged as commercially dominant. There are numerous utility-scale storage technologies under
discussion; those currently in commercial use include compressed air energy storage (CAES), flywheels,
and batteries.
CAES uses off-peak electricity to store air under pressure, typically underground in a cavern or salt
mine. When on-peak electricity is needed, that air is used as input to a natural gas turbine. That turbine
can operate at very high efficiency, as it uses pre-compressed air. So CAES uses some natural gas to
provide peak electricity, but less than a conventional natural gas peaking power plant would require. There
are currently two CAES plants in operation: one in Germany (started up 1978) and one in Alabama (started
up 1991).
Flywheel storage uses off-peak electricity to spin a low-friction flywheel, converting electrical energy
into rotational energy. When peak electricity is needed, that flywheel is used to turn a generator, converting
the rotational energy back into electricity. In early 2009 an agreement to build a one MW flywheel
storage system was announced. This system when complete will provide regulation services to the PJM
interconnection.
There are a number of battery technologies under consideration for utility-scale electricity storage.
There are a handful of pilot and commercial systems installed, and various approaches under development.
Thus far, no specific approach or technology has emerged as dominant.
An alternative approach is “distributed” storage, which includes larger systems that work on the
level of substations,54
as well as household-level systems in the tens of kilowatts. There is currently much
discussion of the potential for plug-in hybrid electric vehicles (PHEVs) to act as distributed storage,
marrying the electricity and transportation systems. The idea is straightforward: cars would plug in to
the grid, and could be either charged with off-peak grid electricity or discharged to power the grid when
demands are high. If many households had PHEVs, the total effective storage capacity would be very large.
PHEVs are not yet available from major automakers. However both automobile manufacturers and some
utilities see PHEVs as an intriguing way to integrate the electricity and transportation systems.

27
V. A High Wind and Solar Future: Scenarios and Implications
Wind and solar currently play small roles in the U.S. electricity mix. This section shows that, while our
current path may lead to significant increases in wind and solar power, many alternative scenarios have
been proposed that include far larger increases. The implications of these scenarios—on build rates, new
transmission needs, and variability—are teased out to provide insight into the scale of the challenge of
achieving a high wind and solar future.
A. Current Trends: The “Business-as-Usual” Scenario
In recent years, a number of policies have been introduced to promote greater use of renewables in
electricity production. Largely because of these policies, the most recent “business-as-usual” (BAU) scenario
from the U.S. Energy Information Administration (EIA)—one which assumes only “on-the-books” climate and
energy policies—shows non-hydro renewable electric generation growing rapidly from 2007 to 2030. However,
in this scenario renewables still only provide 14 percent of electricity in 2030 (Figure 3).55
Figure 3: A “business-as-usual” forecast, showing the U.S. reaching 14 percent renewables by 2030
Non-Hydro
Renewables
8%
Hydro
6%
Oil/Other
2%
Biomass 4%
Wind 3%
Municipal Solid Waste 0.5%
Geothermal 0.5%
Solar 0.5%
Nuclear
18%
Natural Gas
19%
Coal
47%
2030 (Forecasted)
5,124 billion TWh/yr
Source: DOE, March 200956

28
There are significant uncertainties in this type of forecasting. Unknowns include future fossil fuel prices,
legislative changes (notably, the introduction of a national greenhouse gas cap-and-trade system, further
extension of tax incentives for renewable energy, new state renewable portfolio standards, and a possible federal
renewable energy standard), costs of new generation, and future electricity demand. However, this forecast
does suggest that without changes to existing policies, shifts in market conditions, or technology developments
renewables are likely to play a larger role in the U.S. electricity market by 2030 but one that is less substantial
than the role envisioned by some policymakers, experts, and advocates.
B. Alternative High-Renewables Scenarios
A number of policymakers, organizations, and researchers have offered alternative scenarios, in which the
growth of renewables in the U.S. electricity system is accelerated (see Figure 4). These studies vary widely in
their assumptions, the depth of the analyses underlying the results, and their findings.
Figure 4: Business-as-usual (BAU) scenario and some alternatives
2007 2010 2015 2020 2025 2030
0
10
20
30
40
50
60
80
90
100
Gore
ACORE
House bill RPS, 2005
Business as usual
PercentageofU.S.electricitygeneratedfromrenewablesincludinghydro
Year
DOE 20%
wind by 2030Range of Congressional Proposals, 2009
Google
{House bill RPS, 2007 Senate C02
bill, 2008
LEGEND
“ACORE” is a study by the American Council on Renewable
Energy.
“DOE 20% wind by 2030” is the DOE “20% Wind Energy
by 2030” report.
“Google” is Google’s proposal for Clean Energy 2030.
“Gore” is based on data at the Repower America web site.
“House RPS bill, 2005” is the RPS section in HR6 (2005),
not included in the final bill.
“House RPS bill, 2007” is the RPS section in HR6 (2007),
not included in the final bill.
“Range of Congressional Proposals, 2009” shows the range
of proposals Congress was considering as of May 2009.
“Senate CO2
bill, 2008” is DOE’s estimate of the effects of
S2191 (2008).
Notes: Since analyses differ as to their definitions of qualifying renewables, data are adjusted to show the percentage of total U.S. electricity
coming from renewables, including hydropower, in the relevant year for that study. For full references, assumptions, and calculations; see Appendix
2. Some of the Congressional proposals provide mechanisms that in effect reduce the renewables requirement, so actual renewables levels
achieved under these proposals could be lower than shown above.

29
Figure 4 clearly shows the sizable gap between the current trajectory (the BAU scenario) and many of the
alternative proposals. These alternative proposals typically require modest or no technological improvements—
that is, achieving the results they propose does not require new or radically different technologies. Rather, these
results come largely from much greater use of technologies that exist today.
Whether these projections are realistic, economically preferable, or politically viable is arguable. The
critical observation is that, although renewable electricity generation is growing, the United States is not
currently on a path to reach the aggressive renewable electricity goals proposed or advocated by many in
Congress and other organizations.
C. Implications of a High Wind and Solar Scenario
What would it take to make a high-renewable scenario, such as recent Congressional proposals or the DOE
20 percent wind by 2030 scenario, a reality? How much transmission would be needed, and by when? And
could the electricity grid manage that much renewables? There are many uncertainties—technical, economic,
and political—that make answering these questions difficult. Nevertheless, it is possible to bracket, or roughly
quantify, the implications of a high-renewables scenario.
To do so, this analysis defines a “High Wind” Scenario using the DOE analysis of “20 percent wind energy
by 2030” as a starting point.57
This is not to endorse this as a policy goal, but rather because this scenario is
extensively documented and is roughly comparable in scope and ambition to the RPS proposals in the 111th
Congress.
The DOE scenario would require building 280 GW of new wind by 2030.58
Assuming that renewables other
than wind were built at rates corresponding to that in EIA’s “business as usual” scenario, this 280 GW of new
wind would put the U.S at 29 percent renewables by 2030 (see Figure 5).59
Assuming linear build rates (that
is, the same amount of wind is built every year, starting in 2010 and ending in 2030), 280 GW corresponds to
14 GW per year. Alternatively, one could consider a “ramp-up,” in which build rates grow from the actual 8.3
GW installed in 2008 to, for example, 18 GW per year by 2020, and continue at that level to 2030.

30
Figure 5: A “High Wind” scenario with all other renewables achieving the same levels of generation as in
“business as usual.”
Non-Hydro
Renewables
22%
Hydro
6%
Oil/Other
2%
Nuclear
18%
Natural Gas
13%
Coal
39%
Biomass 4%
Wind 17%
Geothermal 0.5%
Solar 0.5%
2030 (Forecasted)
The actual 2008 installations of 8.3 GW was a record year for the wind industry, and one that is unlikely to
be surpassed in 2009. A build rate of 18 GW by 2020 would represent over a doubling of the installation rate
of 2008; however, it is certainly conceivable that the wind industry could accomplish that by ramping up to 18
GW per year by 2020. DOE’s analysis concluded that, “achieving the 20 percent wind scenario by 2030 would
not overwhelm U.S. industry.”60
Furthermore, DOE found no fundamental materials, manufacturing, or labor
barriers to such a ramp-up. Clearly, the wind industry would need to see clear and profitable demand for wind
electricity in order to build at that rate. However there is no reason why that would not be physically achievable.
How much new transmission would be needed to accommodate 280 GW of new wind, and what would that
cost? DOE estimates that 280 GW of new wind generation would require 12,650 miles of new high-voltage
transmission, at an undiscounted cost of approximately $60 billion.61
A separate study estimated that 19,000
miles of new high-voltage (765 kilovolt) transmission lines would be needed, at an estimated cost of $60
billion (2007$).62
This equates to approximately $3 billion per year, for the period 2010 to 2030. To put this in
perspective, U.S. investor-owned utilities currently spend about $6 billion per year on transmission,63
and DOE
estimates total current transmission spending at about $8 billion per year.64

31
An alternative method to estimate transmission costs is to apply the per-kWh costs of transmission needed
to accommodate wind, as estimated in specific wind and transmission planning studies, to this scenario. A
comprehensive review of U.S. transmission studies found that the transmission needed for new wind had a
median cost of 1.5 ¢/kWh.65
This implies a 13-17 percent increase in wind power’s levelized cost.
To summarize, the new transmission needed to accommodate the “High Wind” scenario would probably
cost about $3 to $4 billion per year—a 40 to 50 percent increase in annual transmission spending. If this cost
were charged to the new wind capacity, it would increase the cost of wind by about 15 percent.
In the “High Wind” scenario at least 17 percent of U.S. electricity (MWh) comes from a non-dispatchable
resource in 2030. Can the electricity system manage this level of wind penetration, and if so at what cost? It
is important to recognize that utilities and electricity grid operators have been successfully managing demand
variability since the first electricity systems began operating. The issue therefore is the increased variability
due to wind and solar. As noted above (see Table 2), some countries have already exceeded 10 percent wind,
but 17 percent is certainly beyond U.S. experience. Several studies have examined the impacts of higher wind
penetration rates, and DOE’s review of these studies concluded that 20 percent wind energy “can be reliably
accommodated.”66
The available evidence does suggest that the “High Wind” scenario involves a manageable
level of wind penetration.
As discussed above, non-dispatchable resources impose costs estimated at 0.1¢ to 0.5¢/kWh. It is likely
that higher penetration rates of wind will correspond to the higher end of this range. Assuming 0.5¢/kWh,
therefore, yields an increase in wind costs of four to six percent.67
That is, prices for electricity from wind would
need to increase four to six percent to include the costs of wind integration.
The discussion above focuses exclusively on wind. What might a “High Wind and Solar” scenario look like,
and what might be the implications for build rate, transmission, and variability? Given the high per-kWh costs
of solar, it is likely that even a “High Wind and Solar” scenario would mean a relatively small fraction of solar
in the total electricity mix. To illustrate the implications, this analysis uses as a starting point the “High Wind”
scenario, except that in the “High Wind and Solar” scenario solar generation in 2030 is roughly double its
“business as usual” projection, with wind generation reduced by a corresponding amount (see Figure 6). This
“High Wind and Solar” scenario corresponds to about 18 GW of new solar compared to today.

32
Figure 6: A “High Wind and Solar” scenario with nearly a doubling of solar generation compared to
“business as usual”
Non-Hydro
Renewables
23%
Hydro
6%
Oil/Other
2%
Nuclear
18%
Natural Gas
13%
Coal
39%
Biomass 4%
Wind 16.5%
Geothermal 0.5%
Solar 1%
2030 (Forecasted)
Achieving 18 GW of new solar by 2030 would mean about 900 MW of new solar installations per year, from
2010 through 2030. For comparison, in 2008 340 MW of new solar was installed in the United States.68
So
ramping up to 900 MW/year would be challenging if it was predominantly in the form of PV; however, a number
of CSP plants have been proposed that are in the hundreds of MW, so it is conceivable to reach 900 MW per
year of new solar if CSP plays a role.
The transmission implications of this “High Wind and Solar” scenario are not dissimilar to those for the
“High Wind” scenario. Transmission requirements would be lower if some of the solar was distributed (that is,
building-scale rather than utility-scale).69
Similarly, the variability implications and costs would be qualitatively
similar to the “High Wind” scenario, as solar presents comparable challenges and costs to grid operation. If the
solar was primarily in the form of CSP, then the variability costs could be somewhat lower if the CSP was built
with storage capability.
The key difference between the two scenarios is in first costs for the technologies themselves. As discussed
above, wind’s costs are close to those of new gas-fired generation, while solar costs significantly more.

33
VI. Conclusions
Renewables currently play a small but growing role in the U.S. electricity system. However, legislation now
under consideration, such as a national renewable portfolio standard (RPS) and GHG cap-and-trade program,
could lead to a significantly larger role for renewable electricity. Wind and solar could play a larger role, as wind
and solar resources are plentiful and wind and solar technologies are commercially available. The principal
barriers to greater use are the costs of the technologies (notably for solar), the need for new transmission lines,
and the challenge of integrating variable power sources (that is, power plants whose generation is dependent on
fluctuating resources) into the electricity system.
The technology cost issues are quite different for wind than for solar. Electricity from wind can be cost
competitive with electricity from new coal and natural gas power plants, depending on fuel prices, the carbon
price, and various subsidies. For example, as shown in Table 1, the levelized cost of wind electricity is typically
9 to 12¢/kWh without the production tax credit, compared to, for example, 5 to 10¢/kWh for electricity
from natural gas combined cycle power plants. Solar is considerably more expensive, with utility-scale solar
photovoltaic at 28 to 42¢/kWh without the investment tax credit, and concentrating solar at 24 to 29¢/kWh
without the ITC. A carbon price is unlikely to make current solar technology cost-competitive.
Achieving high levels of wind and solar in the U.S. electricity system—nearly 20 percent by 2030—would
require new transmission spending of $3 to $4 billion per year, about a 40 percent to 50 percent increase over
current transmission spending. If these costs were included in the costs of electricity from wind, then wind
costs would increase by about 15 percent. Studies suggest that 20 percent wind penetration in the electricity
grid is manageable, although there would be costs for integrating this variable power source. These costs would
add four to six percent to the price of wind electricity.
There appears to be no fundament technical, resource, or manufacturing barrier to achieving roughly
20 percent wind by 2030. While uncertain, the available evidence suggests the costs for doing so are not
enormous; adding variability and new transmission costs would likely increase the cost of wind power by roughly
20 percent. This would make wind electricity more expensive than that from natural gas without a carbon price,
but in many cases still less expensive than that from new nuclear or coal with carbon capture and storage.
Solar, in contrast, has quite high first costs, and adding variability and new transmission costs makes solar not
economically competitive at current prices. Significant cost reductions in solar, however, could bring costs down
to where solar could play a role in meeting future electricity needs.

34
Appendix 1: Cost Assumptions and Calculations
To calculate the LCOEs shown in Table 1, the following are assumed: no decommissioning costs or
scrap value, 15 year plant lifetime, and a 9 percent per year capital cost. Costs and LCOEs do not include
the production tax credit or the investment tax credit. Costs and LCOEs do not include land, transmission,
permitting, or other non-hardware costs. See Box: Measuring and Comparing Costs of Electricity Production for
discussion.
Table A1: Cost assumptions for LCOE calculation
Technology First Cost ($/kW)
Operation and
Maintenance
Cost (¢/kWh)
Fuel Cost
(¢/kWh)
Capacity
Factor
Resulting LCOE
(¢/kWh)
Wind ( 1 MW) 1900-2400 1 0 0.32 9-12
Concentrating Solar
Power (CSP)
3800-4800 3 0 0.26 24-29
Utility-scale
photovoltaic ( 10 MW)
5000-7500 1 0 0.26 28-42
Distributed photovoltaic
( 10 kW)
7000-9000 1 0 0.22 46-59
Natural Gas 800 0.5 2.8–8.3 0.70 5-10
Technology-specific major assumptions: CSP assumes no built-in storage. Tracking capability assumed for utility-scale PV, but not for distributed
PV. Natural gas fuel costs of 2.8¢/kWh to 8.3¢/kWh correspond to assumed fuel prices of $4/MBTU to $12/MBTU, at a heat rate of 6900
BTU kWh.
Sources: Author’s estimates, based in part on Black Veatch 200870
and Wiser et al. 2009.71

35
Appendix 2: Assumptions and Calculations for Figure 4
The business-as-usual (BAU) scenario is based on U.S. DOE, March 2009.
The “ACORE” data point—58 percent by 2025—is based on data in ACORE, March 2007.72
Table 1 in
that source provides new renewable capacity for 2025. Assumed capacity factors are shown in Table A2 below.
This new generation was added to 2007 renewable generation (from U.S. DOE, March 2009) to yield total (new
plus existing) renewable generation in 2025. This was then divided by BAU forecasted 2025 generation (from
U.S. DOE, March 2009) to yield the percentage of total generation in 2025 that would come from renewables,
under the Table 1 scenario in ACORE, March 2007.
Table A2: Assumed capacity factors for scenarios
Technology Capacity Factor
Wind 0.32
Solar 0.26
Geothermal 0.70
Biomass/other 0.70
Hydro 0.70
The “DOE 20 percent wind by 2030” data point—29 percent by 2030—is based on data in U.S. DOE,
July 2008.73
That report proposes 305 GW of wind in 2030, including currently existing wind (see Figure 1-3,
page 7). The generation of that 305 GW was calculated, based on the capacity factor shown above in Table
A2. From the BAU scenario (U.S. DOE, April 2009), BAU renewable generation in 2030, excluding BAU wind,
was calculated. To that number the “new” wind 2030 generation was added. That total renewable generation
number was then divided by 2030 total generation. By 2030, coal and natural gas generation were assumed to
be displaced in equal amounts by the new wind generation.
The “Google” data point—65 percent by 2030—is based on data in Google, February 2009.74
That plan
keeps electricity consumption “flat” at 2008 levels. 2008 electricity consumption is based on U.S. DOE, March
2009 data for 2007; a one percent increase was assumed to calculate 2008 total electricity consumption.

36
Renewables are based on capacities shown in Figure 1 in Google, February 2009. Capacity factors are as shown
in Table A2 on the previous page.
The “Gore” data point—76 percent by 2020—is based on data in Repower America, February 2009.75
The 76 percent is the percentage of all electricity generated in 2020 that comes from renewable sources, in
scenario A.
The “House RPS bill 2005” data point—10 percent by 2020—refers to sec. 609 in a version of HR6,
The Energy Policy Act of 2005 (engrossed amendment as agreed to by Senate). Although HR6 was passed into
law, that section was not included in the final bill. That section’s definition of renewables excluded existing
hydropower, so an estimate for current-day hydropower as a percentage of 2020 electricity consumption (5
percent) was added to the 10 percent.
The “House RPS bill 2007” data point—15 percent by 2020—refers to sec. 610 in a version of HR6,
the Energy Independence and Security Act of 2007 (engrossed amendment as agreed to by House). Although
HR6 was passed into law, that section was not included in the final bill. That section’s definition of renewables
excluded existing hydropower, so an estimate for current-day hydropower as a percentage of 2020 electricity
consumption (5 percent) was added to the 15 percent.
The “Congressional proposals 2009” range of 20 to 30 percent includes the RPS discussion draft from
Senator Bingaman, the discussion draft of the “American Clean Energy and Security Act of 2009” introduced
by Representatives Markey and Waxman, and HR 890 and S433 in the 111th Congress (2009). These
proposals exclude existing hydropower, so an estimate for current-day hydropower as a percentage of 2020
electricity consumption (5 percent) was added to their stated 2025 goals.
The “Senate CO2 bill 2008” data point—19 percent by 2030—refers to S2191, America’s Climate
Security of Act of 2007, in the 110th Congress. That bill was not passed into law. The 19 percent data point is
an estimate by DOE of the renewables that would result if the bill were passed.76

37
Endnotes
1. U.S. Department of Energy (DOE), Energy Information Administration (EIA), Emissions of Greenhouse Gases in the
United States 2007, DOE/EIA-0573(2007), December 2008, p. 4. Available at www.eia.doe.gov.
2. EIA, Annual Energy Outlook 2009, DOE/EIA-0383(2009), March 2009. Available at www.eia.doe.gov.
3. Natural gas imports as a percentage of total natural gas consumption increased from 8 percent in 1990 to 20 percent
in 2007. EIA, Annual Energy Review, DOE/EIA-0384 (2007), June 2008, p. 183. Available at www.eia.doe.gov.
4. See e.g. Morgan, G., J. Apt, and L. Lave, The U.S. Electric Power Sector and Climate Change Mitigation, prepared for
the Pew Center on Global Climate Change, June 2005, table 7. Available at www.pewclimate.org.
5. There are CO2 emissions associated with material manufacturing and renewable plant construction, and in some cases
plant operation (for example, gasoline used by plant maintenance vehicles). These emissions, however, are quite small relative to
those resulting from burning of fossil fuels for electricity production.
6. Wind and solar photovoltaic (PV) technologies do not use any water, however concentrating solar power (CSP)
technologies do require water.
7. See, for example, Kelly, M. and S. Tegen, “Economic Development Impacts of 20% Wind,” Poster, National Renewable
Energy Laboratory, June 2007, available at www.nrel.gov.
8. DOE, 20% Wind Energy by 2030, DOE/GO-102008-2567, July 2008. Available at www.20percentwind.org. Wind
capacity (GW) is not directly comparable to total capacity (GW), due to wind’s lower capacity factor.
9. Assuming average insolation of 6.0 kWh/m2
/day, PV conversion efficiency of 10 percent, U.S. electricity consumption
of 4,000 TWh/year. Such a system would be absurdly impractical for many reasons, notably it would require huge amounts of
storage to account for the variability of electricity output. Nonetheless, this is illustrative of the vast amount of solar energy that
could theoretically be tapped.
10. EIA, Annual Energy Review, June 2008, pp.228, 260.
11. American Wind Energy Association (AWEA), AWEA Annual Wind Industry Report—Year Ending 2008. Available at www.
awea.org.
12. As shown in Table 1, wind’s current cost (LCOE) range has some overlap with that of electricity from natural gas. This
means that, in some cases, wind can produce electricity at or below the LCOE of electricity from natural gas.
13. American Wind Energy Association (AWEA), U.S. Wind Energy Projects as of 12/31/08, database available at http://
awea.org. (Data viewed April 2009).
14. DOE, 20% Wind Energy by 2030, July 2008, p. 8.
15. “Technical potential” excludes those areas not suitable for wind turbines (such as steep slopes, national parks, and urban
areas), but does not consider cost or economic viability. For details on these technical potential estimates, see Black Veatch, 20
Percent Wind Energy Penetration in the United States, Final report, October 2007, available at www.20percentwind.org.
16. Assuming a wind capacity factor of 0.32. U.S. total electricity consumption from U.S. Department of Energy, Annual
Energy Outlook 2009, March 2009.

38
17. The production tax credit (PTC) provides a tax credit, currently valued at 2.1¢/kWh, for electricity produced from wind.
For more information on the PTC, see http://dsireusa.org/.
18. Cost analyses of wind projects from 1998 to 2007 show year-to-year oscillations but no overall decrease, suggesting
that the cost curve has bottomed out. See U.S. Department of Energy, Annual Report on U.S. Wind Power Installation, Cost, and
Performance Trends: 2007, DOE/GO-102008-2590, May 2008, figure 14. Available at www.eere.energy.gov.
19. There are carbon emissions associated with the manufacturing and construction of wind turbines. In addition, if
natural gas is used to “firm” wind power, there are carbon emissions associated with that natural gas use. See Katzenstein,
W. and J. Apt, “Air Emissions Associated with Wind and Solar Power,” Environmental Science and Technology, 2009, 43 (2),
pp. 253-258.
20. This discussion focuses on utility-scale wind farms, which consist of multiple large (1 MW or larger) wind turbines.
Smaller wind turbines are commercially available for distributed applications, but are not discussed in this report.
21. Solar Energy Industries Association (SEIA), US Solar Industry Year in Review 2008, March 31, 2009, p. 4. Available
at www.seia.org.
22. For a helpful explanation of PV systems, see the DOE’s “Photovoltaic Basics” at www1.eere.energy.gov/solar/pv_basics.html.
23. National Renewable Energy Laboratory (NREL), Annual PV Solar Radiation Map. Available at www.nrel.gov. The higher
PV electricity output due to increased sunlight can be partially offset by higher ambient temperatures, which decrease PV output.
24. The investment tax credit (ITC) provides a 30 percent federal tax credit for qualifying PV systems. For more information
on the ITC, see http://dsireusa.org.
25. Wiser, R., G. Barbose, and C. Peterman, Tracking the Sun, LBNL-1516E, February 2009, p. 1. Available at http://
eetd.lbl.gov/ea/EMS/re-pubs.html. There were, and will continue to be, significant year-to-year price fluctuations due to policy
changes, economic conditions, and demand/supply imbalances.
26. It should be noted that the module cost data could be reflecting actual cost decreases offset by increased profits.
27. Press release entitled, “First Solar Passes $1 Per Watt Industry Milestone,” dated 24 February 2009, available at
firstsolar.com.
28. Wiser, R., et al., Tracking the Sun, February 2009, p. 10.
29. Solar Energy Industries Association, US Solar Industry Year in Review 2008, March 2009, p. 7.
30. For more information on state-by-state electricity market regulation, see EIA, “Status of Electricity Restructuring by
State,” available at www.eia.doe.gov.
31. The Brattle Group, Transforming America’s Power Industry, November 2008. p. 35. Available at www.eei.org.
32. North American Electric Reliability Corporation (NERC), Accommodating High Levels of Variable Generation, April
2009, available at www.nerc.com.
33. An example of such a firm is the American Transmission Company—see www.atcllc.com.
34. National Council on Electricity Policy, Electricity Transmission: A Primer, June 2004, p. 76, footnote 1 in appendix.
Available at www.raponline.org.
35. See, for example, Milligan, M. and K. Porter, “Determining the Capacity Value of Wind: An Updated Survey of Methods
and Implementation,” presented at Windpower 2008, June 2008, Houston TX. Available at www.nrel.gov.
36. Smith, J., et al., “Utility Wind Integration and Operating Impact State of the Art,” IEEE Transactions on Power
Systems, August 2007.
37. DOE, Annual Report on U.S. Wind Power Installation, Cost, and Performance Trends: 2007, May 2008, pp. 6,7.

Wind Solar Electricity Report

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Viewers also liked

Viewers also liked (12)

Similar to Wind Solar Electricity Report

Similar to Wind Solar Electricity Report (20)

More from Glenn Klith Andersen

More from Glenn Klith Andersen (20)

Recently uploaded

Recently uploaded (20)

Wind Solar Electricity Report